1. Field
The present disclosure relates to operations in a wellbore associated with the production of hydrocarbons. More specifically, the disclosure relates to systems and methods for reducing or removing condensate blockage in and around a natural gas wellbore.
2. Description of the Related Art
During production of natural gas from a wellbore, as the flowing bottomhole pressure declines to less than the dew-point pressure of the natural gas, heavier components of natural gas condense into liquid and dropout of the gas phase. Condensation of liquids results in near-wellbore formation damage (or blockage), which is caused by not only accumulation of condensed hydrocarbons, but also by the accumulation of formation water during the production process from most gas fields. The severity of liquid condensation and accumulation around wellbores depends upon the composition of gas, operating pressure and temperature, and the reservoir rock properties such as porosity and permeability. In general, a greater pressure drop, lesser near-wellbore temperature, heavier gas contents, lesser near-wellbore porosity, and lesser near-wellbore permeability are contributing factors for this type of formation damage. The accumulated liquids can impede gas flow paths from the reservoir towards the wellbore once they reach a critical saturation level. Consequently, gas production rates and overall recovery can be significantly reduced. In many severe cases, the well has to be abandoned because of uneconomical well performance.
Similarly, for low pressure gas reservoirs, when natural gas enters into a wellbore, enhanced condensation of liquids can occur as the natural gas rapidly expands within the wellbore and cools in transit to the surface. Free liquids, or “condensates” (oil and water), from the reservoir can also enter a wellbore along with the natural gas being produced. Initially, the natural gas stream in transit to the surface can carry these liquids up-hole by viscous drag forces. However, as reservoir pressure depletes in mature wellbores, the velocity of the gas stream is often reduced to less than a “critical velocity” that is required to carry the liquids to the surface. Thus, at less than the critical velocity, liquids begin to accumulate in the wellbore in a phenomenon called “liquid loading.” Liquid loading in a low-pressure wellbore can inhibit the production of natural gas from the wellbore. For instance, accumulation of liquids increases the backpressure against the flowing bottom hole pressure, which can result in a cessation of production. Additionally, accumulated liquids can interact with an inner lining of production tubing, yielding corrosion and scaling.
Well deliquification and liquid-unloading techniques can be employed to remove accumulated liquids from a wellbore and near-wellbore formation. Generally, for well-deliquification, submersible pumping systems can be installed in a wellbore, or techniques such as plunger lifting can be employed, in which a plunger is raised through the tubing of a wellbore to sweep liquids to the surface for removal. Typically, these procedures, which attempt to remove liquid that has already accumulated in a wellbore, are associated with relatively great operating costs and often require temporarily shutting down, or cycling the wellbore. Most techniques suggest controlling condensate issues (within wellbores and near-wellbore areas) by maintaining flowing bottomhole wellbore pressure greater than the dew-point conditions to produce gas economically. This conventional approach, however, has many limitations including early well abandonment because of the rapid pressure decline in many gas-condensate reservoirs.